Method of operating oil well using electric centrifugal pump unit

ABSTRACT

The invention relates to the field of mining, specifically to oil extraction using electric centrifugal pump units having a frequency-controlled electric motor, and serves to fully automate oil well operations using an electric centrifugal pump. A method of operating an oil well using an electric centrifugal pump unit, wherein temperature is regulated by means of changing the rotational speed of a pump shaft, which is a novel use of operating temperature as “feedback” for monitoring the state of the centrifugal pump. Using the invention allows for fully automating the process of launching, putting into an operational mode, and monitoring the operation of the oil well using the electric centrifugal pump unit, which, in turn, increases the overall reliability of the equipment (electric centrifugal pump unit).

FIELD OF THE INVENTION

The invention relates to the mining sphere, specifically, to oil production using electrical submersible pumps (ESPs) with variable-frequency drives, and represents a means of the complete mechanization of oil well operation using an electrical submersible pump.

BACKGROUND

Patents exist for the partial mechanization of ESP rate stabilization by means of a control station with a variable-frequency submersible drive.

In the prior art, the “Method of the operation of a marginal well using an electrical pump with a variable-frequency drive” (application No. 97110817/03 dated Jun. 19, 1997) is known.

The known method uses intermittent cycles including pump start-up with increasing power-supply frequency and fluid pumping at a preset frequency. After pressurization to the preset value in the production string during the given cycle, the power-supply frequency is reduced until pumping stops with the further maintenance of the maximum frequency ensuring fluid inflow from the reservoir at which the pump does not resume supply, and after the inlet pressure reaches the preset value during inflow, the cycle is repeated with the pumping resumed by switching it to a higher frequency with the difference that in the current cycle inflow phase, the pump's power-supply frequency is modulated in the range of frequency values matching the pump's parameters changing in the process of inflow when pumping is stopped and resumed.

The prior art discloses the method of N. P. Kuzmichev “Method of short-term well operation using a submersible pump with an electrical drive” (Kuzmichev's method) (application number: 2005128382/03 dated Feb. 4, 2011).

The prior art also discloses the method of A. A. Chudnovsky, S. I. Zaitsev, A. V. Davydov and IstvanGoczi “Method of well fluid production” (RF patent No. 2190087).

The intermittent pumping-out of well fluid and waiting for the accumulation of well fluid to a certain level is considered in the known analogues.

The prior art also discloses control stations IRZ-5121-400, ELECTON-05F-400, ETALON-CR-400, ORION-03-400 and others, where automatic start-up and operation take place using data from the pressure-and-temperature gage (telemetric system) at the ESP inlet. Pressure parameters are transmitted from the telemetric system to the control station as feedback, in order to adjust the pump's speed to align with the system's preset operation per “submersible pump-inflow from reservoir.” E.g. at an inflow of 20 cubic meters of fluid from the reservoir per day, an ESP unit with a capacity of 35 cubic meters per day at an AC frequency of 50 Hz needs to be operated at a lower speed.

In all quoted analogues, the main technical disadvantage is the neglecting of the thermal state of the centrifugal pump, specifically, the rate of ESP temperature change. In all quoted analogues, current load on the submersible motor is taken as the basis. However, the same current load can match various inlet pressure values, gas content, water cut, gas factor, bubble-point pressure. Such uncertainty in terms of dependence doesn't allow for effectively responding to a change in current intensity. The intensity of electric current is not indicative of the ESP's condition.

The prior art discloses the “Method of the automatic control of an ESP with an AC electrical motor.” According to this method, the centrifugal pump is operated at such a pump speed that the temperature in the first pump section remains constant. Automatic control of the ESP uses an AC electrical motor with the temperature in the first pump section used as feedback (2012111621/06 dated Mar. 26, 2012). However, inlet fluid temperature is not taken into account, which doesn't allow for determining the temperature increase in the pump due to generated heat.

Therefore, all of these control stations are semi-automatic for the purposes of start-up, rate stabilization and the monitoring of ESP operation, since:

a) pump inlet pressure cannot be used as a feedback parameter this way;

b) optimal pump inlet pressure cannot be identified by the control station's service technicians;

c) ESP condition is neglected, because ESP temperature may change from 10 to 100 degrees, depending on the presence of gas in the lifted fluid. The high temperature of the pump may cause the ESP's failure due to the reduction in electrical resistance of the cable-motor system or scaling inside the pump;

d) the pump's temperature is insufficient for feedback, because the fluid temperature at pump inlet and the condition of the submersible electrical motor are disregarded. E.g. the deeper the ESP's installation, the higher the temperature at pump inlet. Therefore, with an identical pump temperature on similar units, the increase in temperature in the pump with the lower inlet temperature will be higher than in the pump with the higher inlet temperature. This may lead to an erroneous conclusion as to the identical condition of the units and the need for identical actions to adjust the pumps' temperature, e.g. through an identical change in pump speed. In fact, where the temperature is higher, it's necessary to reduce the AC frequency to a greater extent. Let's designate the temperature difference in the pump and in the pump outlet as a relative temperature.

The applicant proposes the above “Method of the automatic control of an ESP with an AC electrical motor” as the closest analogue. In this application (2012111621/06 dated Mar. 26, 2012), the pump's temperature is considered without allowance for the gas-and-fluid mixture's temperature at pump inlet. The change in relative pump temperature is given consideration for the first time, which eliminates the shortcomings under items a)-d). Therefore, I propose the “Automatic electrical submersible pump unit”—the completely-automatic process of the operation of an electrical submersible pump with a variable-frequency drive (FIG. 1).

SUMMARY OF THE INVENTION

The challenge to be solved using the claimed invention consists of the artificial-lift operation of the oil well with the installation of an electrical submersible pump.

The technical result of the claimed invention is the complete mechanization of start-up, rate stabilization and monitoring of operation, which will eventually result in enhancement of the equipment's (ESP's) reliability and a reduction in oil-production cost.

The technical result of the claimed invention is attained through temperature adjustment by changing the pump's speed, whereby operating temperature is regarded for the first time as feedback for monitoring of the centrifugal pump's condition, i.e. when the artificial-lift operation of the oil well is organized by the installation of an electrical submersible pump with a pumping pressure allowance of 25% installed at the designated depth. Operating mode and parameters are entered into the control station, unit integrity is checked, initial frequency ω_(in) is set at 50 Hz AC, pump temperature limits are set so that the pump's temperature is lower than admissible temperature T_(p)<T_(adm), operation parameters are recorded: initial pressure at pump inlet P_(in0), initial pump temperature T_(in0), current intensity I; ESP is put into operation with simultaneous recording of the ESP's inlet pressure P_(inlet), pump temperature T_(w) and temperature at pump inlet T_(f). At the same time, the pump is operated with the pressure at the ESP inlet being higher or equal to the bubble-point pressure P_(inlet)≥P_(bpp). When the ESP inlet pressure becomes equal to the bubble-point pressure P_(inlet)=P_(bpp), temperature T_(f) and T_(w) are recorded, well production rate Q_(f0) is measured, ESP rate is stabilized at constant or increasing (max by 10%) pressure at pump inlet over one or more hours, production rate Q_(f), pressure at pump inlet P_(inlet), temperature at pump inlet T_(f), pump surface temperature T_(w), current intensity I_(oper) are recorded. At the same time, the difference between the pump's surface temperature T_(w) and the pump's inlet temperature T_(f) remains constant or reduces by max 10% and stabilizes; and with the pressure at the pump inlet P_(inlet) being below the bubble-point pressure P_(bpp) and an increasing difference between T_(w)−T_(f), they measure bottomhole pressure P_(bh1), K-well productivity factor (m3/day/atm), pressure of the fluid column from the bottomhole to the level of pump suction P_(fluid column), initial pressure at pump inlet P_(inlet0), reservoir pressure P_(res.) equal to the pressure at the bottomhole of the idle well, and define the increase in well production rate using the formula: Q₁=k(P_(res.)−P_(bh1)) with the pressure of P_(bh1)=P_(inlet1)+P_(fluid column), where P_(bh1)-bottomhole pressure, P_(fluid column)=P_(inlet0). K-well productivity factor (m3/day/atm) is defined using the formula: Q₂=k(P_(res.)−P_(bh2)) with the pressure of P_(bh2)=P_(inlet2)+P_(fluid column), where P_(bh2)—bottomhole pressure after an operating time of t₁; difference in the increase in well production rate is defined as follows: ΔQ=Q₂−Q₁=k(P_(inlet1)−P_(inlet2)), then, Z ratio is defined:

$Z = \frac{Q_{opt} + {\Delta \; Q}}{Q_{opt}}$

the pump speed is reduced by Z, and the unit rate is stabilized with the pump inlet pressure P_(inlet) above the bubble-point pressure, the centrifugal pump speed increases based on the following relationship: ΔQ_(f)=k(P_(inlet)−P_(bpp)), AC frequency and current intensity are calculated along with measuring of the pump temperature T_(w), ESP operation continues with the values of the most optimal production rate Q_(f,optimal), dynamic level H_(d), current intensity of the unit I_(oper) and pump surface temperature T_(w).

In the particular case of implementation of the claimed technical solution, the following operating parameters are entered into the control station: k—well productivity factor, m³/day*MPa; initial reservoir pressure-P_(res), MPa; pump operating temperature-T_(w).

In the particular case of implementation of the claimed technical solution, for the purposes of ESP leak-off test, it is necessary to open the valve, set the rotation direction, close the flowline valve at the X-tree and start up ESP, pressurize up to 40 atm at the X-tree, switch off ESP and then check pressure at the X-tree over the course of 15 minutes.

In the particular case of implementation of the claimed technical solution, temperatures T_(f) and T_(w) are recorded, and the process of the unit's start-up is repeated, provided the pump temperature T_(p) is equal to the pump inlet temperature T_(f) and the current intensity I_(oper) is equal to 0.

In the particular case of implementation of the claimed technical solution, the pump speed is reduced by Z:

In the particular case of implementation of the claimed technical solution, the pump operation continues with a reduced difference (T_(w)-T_(f)) of more than 10% due to the increase in flow temperature at the pump inlet T_(f), with the values of T_(f), T_(w), well-production rate Q_(f), dynamic level H_(d), pump suction pressure P_(suction), current intensity I_(oper), voltage U_(oper), AC frequency.

In the particular case of implementation of the claimed technical solution, the ESP is shut down for accumulation with a decreasing pressure at pump inlet and a pump temperature increase to the value of the operating temperature of the extension cable until the pump suction pressure reaches the value of P_(suction)=1.2 P_(bpp) and in the condition of

${H_{{curr}.{head}} = {{\frac{H_{{head}{({\omega \; {st}})}}}{Z^{2}}\mspace{14mu} {at}\mspace{14mu} T_{w}} \geq T_{adm}}},$

where H_(curr.head)—current head, H_(head(ωst))—head of the centrifugal pump at a standard AC frequency (50 Hz), at the value of P_(suction)=1.2 P_(bpp) the unit is put into operation with the values of accumulation time t_(acc); pumping-out time t_(pump-out), operating current I_(oper), voltage U_(oper), initial and final pump surface temperature T_(w, initial), T_(w,final).

In the particular case of implementation of the claimed technical solution, in the process of rate stabilization with the pump inlet pressure P_(inlet) above the bubble-point pressure, the pump speed is increased based on the following relationship: ΔQ_(f)=k(P_(inlet)− P_(bpp)), AC frequency and current intensity are calculated, at the same time the pump temperature is measured T_(w), and ESP operation is continued with the values of the most optimal production rate Q_(f,optimal), dynamic level H_(d), current intensity I_(oper) and pump surface temperature T_(w).

BRIEF DESCRIPTION OF THE DRAWINGS

The details, attributes and advantages of the present invention will follow from the below description of the embodiments of the technical solution containing the drawings that show:

FIG. 1—electrical submersible pump unit with a variable frequency drive;

FIG. 2—a graph of pressure changes at the pump inlet;

FIG. 3—a graph of the temperature of the pump T_(w) over time;

FIG. 4—a graph of the temperature of the pump T_(f) over time;

FIG. 5—a graph of the temperature of the pump over time;

FIG. 6—motor temperature vs. time curve;

FIG. 7—pump temperature vs. current frequency.

The following items are numbered in the figures:

1—submersible electrical motor; 2—seal section; 3—centrifugal pump; 4—pump section; 5—pump section; 6—pump temperature gage; 7—pump inlet temperature gage; 8—pump inlet pressure gage; 9—cable line; 10—control station; 11—tubing strings; 12—valve with pressure gauge; 13—X-tree; 14—centrifugal pump suction.

DETAILED DESCRIPTION OF THE INVENTION

The electrical submersible pump unit (ESP) (FIG. 1) consists of the following: submersible electrical motor (1), seal section (2), centrifugal pump (3), pump section (4, 5), pump surface temperature gage (6), pump inlet temperature gage (7), pump inlet pressure gage (8), cable line (9), control station (10), tubing strings (11), valve with gage (12), X-tree (13), centrifugal pump suction (14).

The ESP is activated by the submersible AC electrical motor fed from the control station with AC frequency over the cable line (9) and rotates the centrifugal units in the pump mounted on the shafts of the centrifugal pump and sections (4, 5) coupled with the electrical motor shaft.

The centrifugal force that's created pumps the gas-and-fluid mixture through the openings in the bottom part of the pump, pumping it from vessel to vessel and further via tubing string to the oil gathering system. The ESP is installed in the well production string, and hung from the tubing string secured to the X-tree. The X-tree is tightly connected to the oil gathering system. The cable line (9) feeding the electrical motor is secured to the tubing string and connected to the control station (10) via a tight slot in the X-tree.

The control station is designed for start-up (shutdown), uninterrupted supply of alternating current over the cable line to the submersible electrical motor, serves for uninterrupted control of the cable line's insulation resistance, the measuring of AC frequency, the receipt of information from the sensors (6, 7, 8) transmitted via the cable line.

Automatic control of the ESP is only possible through the thermal state of the centrifugal pump. Therefore, the only parameter enabling definitive control for the entire ESP is the rate of change of the pump's relative temperature. The pump's relative temperature depends on the thermal parameters of the pump, the properties of the produced fluid.

Depending on the gas content at the pump suction, the pump's relative temperature changes definitively: it depends on the free gas content in the gas-and-fluid mixture at the pump suction. Gas content at the pump suction depends on the gas-oil ratio, bubble-point pressure, pump inlet pressure, water cut. Therefore, the pump's relative temperature can serve as feedback for automatic control of the ESP—the creation of unmanned technology.

The pump surface's relative temperature is calculated using the following formula:

$\begin{matrix} {{\Delta \; T} = {{T_{w} - T_{f}} = {\frac{\phi \mspace{14mu} q_{0}R_{2}P_{inlet}P_{bpp}}{1 - {\phi \; 2\left( {1 - W} \right){hP}_{atm}G}}\mspace{14mu} \left\{ {\frac{1}{\alpha} + \frac{\delta_{ins}}{\lambda_{ins}}} \right\}}}} & (1) \end{matrix}$

where: φ—gas content at the pump inlet, unit fraction; q₀—thermal capacity of the pump, kW/m³; R₂-radius of the external surface of the pump enclosure, m; P_(inlet)—pump inlet pressure, atm; P_(bpp)—bubble-point pressure, atm; W— water content in the well product, unit fraction; h—head of one pump unit with respective gas content in the mixture, atm; G—gas-oil ratio, m3/m3; P_(atm)-atmospheric pressure, atm; α—metal pump enclosure heat-transfer factor, W/m²*° C.; λ_(ins)-thermal-conductivity factor of the gas layer at the external pump surface, W/m²*° C.; δ_(ins)—gas thickness at the external pump surface, m; T_(f)—mixture temperature at the pump inlet, ° C.; T_(w)—pump surface temperature, ° C.

For the purposes of well operation, it is first necessary to select the ESP unit suitable for a production rate with a pump head allowance of 25% and depth of installation in the well.

The following operating parameters are entered into the control station: k—well productivity factor, m3/day*MPa (from 0.1 to 1 or more, depending on location in the well); initial reservoir pressure—P_(res), MPa; pump operating temperature—T_(w).

Allowable temperature T_(adm) (this temperature can be equal to the operating temperature of the cable line, for Russian cable lines less than 230° C.), ° C.; initial AC frequency—ω_(in), Hz; optimal ESP capacity—Q_(opt)(ESP capacity at a frequency of ω_(in)=50 Hz for Russian units), m3/day; current intensity of the motor I_(oper), A; voltage U_(oper), V; head created by the ESP at a standard frequency of 50 Hz—H_(head(ω)); P_(bpp)—bubble-point pressure.

Before ESP start-up, one has to make sure that the flow line is open (valve 12), rotation direction is straight and clockwise, pressure and rotation direction is right-handed. It is necessary to close the flow-line valve (12) at the X-tree, start up the pump, pressurize to 40 atm at the X-tree and shut down the pump. X-tree pressure will remain constant (pressure drop to 38 atm over 15 minutes is allowed)—the unit is tight. Otherwise, the unit is not tight.

Thereafter, initial frequency coin, pump temperature limits T_(p)<T_(adm) are set. Temperature T_(adm) (e.g. operating temperature of the cable line adjacent to the pump-allowable temperature (130° C.) 230° C. for Russian ESPs, (standard) thermal-resistant flat part adjacent to the centrifugal pump). ESP is put into operation; at the same time, pressure P_(inlet) at ESP inlet, pump surface temperature T_(w) and pump inlet temperature T_(f) are recorded. At the same time, pump inlet pressure (FIG. 2), temperature T_(w) (FIG. 3) and inlet temperature T_(f)(FIG. 4) curves are built. Before start-up, initial pressure P_(inlet0), initial pump temperature T_(w0) are recorded. At the same time, current intensity I is recorded.

1. The pump remains in operation until the following value is reached:

P _(inlet) ≥P _(bpp)  (2)

2. When the following equation is attained:

P _(inlet) =P _(bpp)  (3)

T_(f) and T_(w) temperatures are recorded, the curves of dependence of P_(inlet), T_(f), T_(w) and current intensity I on time are built, and the well production rate Q_(f0) is determined.

3. That said, if the pump inlet pressure remains unchanged for one or more hours or increases slightly (by no more than 10%), the process of ESP start-up is considered completed. At the same time, the production rate Q_(f), pump inlet pressure P_(inlet), pump inlet temperature T_(f), pump surface temperature T_(w), current intensity I_(oper) are recorded as the current parameters to be communicated to the company's process engineer (geologist).

4. At the same time, the difference T_(w)−T_(f) remains constant or reduces to a certain extent (by no more than 10%) and stabilizes.

5. If the condition T_(f)=T_(w) is met during unit start-up, the current intensity I_(oper) is checked: if the current intensity is equal to 0, the unit start-up process is repeated. Otherwise, it is necessary to check the unit's integrity.

6. If the difference (T_(w)−T_(f)) reduces by more than 10% due to growth in flow temperature T_(f) at the pump inlet, operation of the centrifugal pump is continued: the process engineer receives the values of T_(f), T_(w), well-production rate Q_(f), dynamic level H_(d) (pump suction pressure P_(suction)), current intensity I_(oper), voltage U_(oper), AC frequency.

7. If the pump inlet pressure P_(inlet) continues dropping to become lower than the bubble-point pressure P_(bpp), so that the difference T_(w)−T_(f) grows, then, based on the formula:

Q1=k(P _(res.) −P _(bh1)) at the pressure of P _(bh1) =P _(inlet1) +P _(fl.col)  (4)

Q₁—fluid production rate (m3/day) at the bottomhole pressure of P_(bh1), where k—well productivity factor, m3/day*PMa; P_(bh1)—bottomhole pressure, P_(fl.col)=P_(inlet0), P_(fl.col)—pressure of the fluid column from the bottomhole to the level of the pump suction, P_(inlet0)— initial pump suction pressure, P_(res.)-reservoir pressure equal to the bottomhole pressure of the idle well. If the pump inlet pressure drops:

Q2=k(P _(res.) −P _(bh2)) at the pressure of P _(bh2) P _(inlet2) +P _(fl.col)  (5)

where Q₂—fluid-production rate (m3/day) at P_(bh2)—bottomhole pressure after operation time t₁. After we define the difference ΔQ (increase in well production rate) between (5) and (4), we have:

ΔQ=Q ₂-Q ₁ =k(P _(inlet1)-P _(inlet2))  (6)

8. Z ratio is further defined:

$\begin{matrix} {Z = \frac{Q_{opt} + {\Delta \; Q}}{Q_{opt}}} & (7) \end{matrix}$

9. The pump speed is reduced by Z:

$\begin{matrix} {\omega_{1} = \frac{\omega_{st}}{Z}} & (8) \end{matrix}$

Further, the pump temperature is checked, and the dependency curves are built (FIG. 6).

11. The dependency curves are built (FIG. 7) T_(w)=f(ω).

12. Current ESP head is checked:

$\begin{matrix} {H_{{curr}.{head}} \geq \frac{H_{{head}{({\omega \; {st}})}}}{Z^{2}}} & (9) \end{matrix}$

where: H_(curr.head)—current ESP head at the frequency of ω_(i) (i takes the values of process steps 1, 2, 3, etc.)

13. By repeating items 6-8 i times, i.e. checking items 6-8 until

$\frac{\Delta \; T_{w}}{\Delta\omega} = {0 \pm 0.05}$

is reached and checking for the presence of condition (9), we see that:

$\begin{matrix} {\frac{\Delta \; T_{w}}{\Delta\omega} = {0 \pm 0.05}} & (10) \end{matrix}$

where ΔT_(w)—change in the pump's surface temperature, Δω—change in current frequency.

14. Then, we consider the process of the unit's rate stabilization completed.

15. The process engineer (geologist) receives: the new frequency ω₁, new production rate Q₁, new pump inlet pressure P_(inlet), current intensity I_(oper1).

Intermittent Operation (Short-Term ESP Operation)

If the pump's suction pressure drops, and the pump's temperature increases to the allowable value, e.g. to the allowable temperature of the cable line attached to the pump enclosure, and the following condition is met:

$\begin{matrix} {H_{{curr}.{head}} = {{\frac{H_{{head}{({\omega \; {st}})}}}{Z^{2}}\mspace{14mu} {at}\mspace{14mu} T_{w}} \geq T_{adm}}} & (11) \end{matrix}$

H_(curr.head)—current head, H_(head(ωst))—head of the centrifugal pump at a standard AC frequency (50 Hz). Then, ESP is shut down for the period of t_(acc)—accumulation time where the pump's suction pressure becomes

P _(suction)=1.2P _(bpp).  (12)

When P_(suction)=1.2 P_(bpp), the pump unit is put into operation, and the dependency curve is built:

T _(w) =f(t)  (13)

At the pump temperature:

T _(w) =T _(p,adm)  (14)

the ESP is shut down for accumulation.

The process engineer receives: accumulation time t_(acc); pumping-out time t_(pump-out), operating current I_(oper), voltage U_(oper), pump surface temperature T_(w, initial), T_(w,final) (initial and final pump surface temperature).

At this point, we complete the process of ESP rate stabilization in short-term operation mode.

Optimizing ESP type and size

It is not uncommon that, in the process of ESP design for a specific well, some errors are made due to the unreliability of well data.

Therefore, after ESP start-up and its rate stabilization, the pump inlet pressure P_(inlet) turns out to be higher than the bubble-point pressure. This means that there is a possibility of increasing oil production. For this purpose, it is necessary to increase the centrifugal pump's speed.

ΔQ _(f) =k(P _(inlet1)-P _(bpp))  (6.1)

We calculate the alternating current frequency using the following formula:

$\begin{matrix} {Z = \frac{{\Delta \; Q_{f}} + Q_{f}}{Q_{f}}} & (7.1) \end{matrix}$

Q_(f)—fluid production rate until the frequency changes, m3/day, ΔQ_(f)—fluid production rate increase after a change in pump speed, Z—non-dimensional value. Q_(f)—fluid production rate until the frequency changes, ΔQ_(f)—fluid production rate, Z—ratio.

At the same time, the current intensity will increase and become equal to:

I _(z) =Z ³ I _(oper)

I_(oper)—current intensity at the production rate of Q_(f), Iz—current intensity after an increase in production rate by ΔQ_(f), i.e. with the cubic dependency of Z factor.

Therefore, a further change in alternating-current frequency will take place simultaneously with measuring the pump temperature T_(w) with the following inequation:

T _(w) ≤T _(adm)

At this point, we complete the process of testing well capabilities, the process engineer receives the following parameters: the most optimal production rate Q_(f, optimal), dynamic level N_(d), current intensity I_(oper) and the pump's surface temperature T_(w).

1. Case study of ESP ratestabilization

1.1. As an example, let's review well No. 236 at field N.

The expected production rate is 18 m³/day at the dynamic-fluid level in the well (measured depth) N_(d)-1600 m (TVD 1420 m). Pressure in the oil-gathering line is 14 atm. Friction resistance in the tubing is assumed to be equal to 5 atm (with a friction allowance of 10 atm). Total required head is 1900 m. Considering the head allowance of 25%, the necessary head is 2350 m. Based on the well productivity factor, we select ESP 5-20-2350. Let's assume that the bubble-point pressure is equal to 110 atm. GOR is equal to 140 m³/m³. Vertical depth of the well Hv=2680 m. Density of oil from the well is assumed to be equal to 752 kg/m³. Reservoir water density is 1004 kg/m³, reservoir temperature is 82° C., downhole gradient pressure is 0.03° C. per 1 m of hole. Well productivity factor is equal to k=0.11 m³/day/atm.

Optimal pump suction pressure P_(opt.suct)=P_(bpp)=110 atm. Then, the fluid column in the well is equal to:

$\begin{matrix} {H_{column} = \frac{\rho_{oil}}{g\; \rho_{mix}}} & (16) \\ {\rho_{mix} = \left( {{\rho_{oil} + {\left( {1 - W} \right)\rho_{w}g}} = {9.8\mspace{14mu} m\text{/}c^{2}}} \right.} & (17) \end{matrix}$

where ρ_(mix)—mixture density; ρ_(oil)—oil density; ρ_(w)—water density; W— water content in the product.

Let's assume that ρ_(oil)-852 kg/m3; ρ_(w)-1004 kg/m3; W—0.23

Mixture density: ρ_(mix)=(852*(1-0.23)+0.23*1004)=656+231+887

Fluid column:

$\begin{matrix} {H_{column} = {\frac{110*101325\frac{\mathcal{H}}{\mathcal{M}^{2}}}{9.8*887} = {\frac{12135650}{8692} = {1396\mspace{14mu} m}}}} & (18) \end{matrix}$

101325 n/m²=1 atm−reduction factor.

By deducting from the vertical depth of the hole H_(column)=1396 m, we have the dynamic vertical level:

H _(d) =H _(well) −H _(column)=2680−1396=1284 m

or measured depth:

H _(d.md) =H _(d)+160=1284+160=1444 m

where 160 m is defined based on the directional log; H_(d.md)—dynamic level, measured depth (production string). Directional log is the difference between the measured hole depth from the vertical depth (defined by directional survey tool) and is constant for each well.

To define the depth for ESP installation, let's assume that the unit has no separator and conforms to the “Operating procedure . . . ” applied by oil-production companies, that a gas content of 25% (φ=0.25) is allowed at the pump inlet.

Then, the gas content at the pump suction is equal to:

$\begin{matrix} {\phi = \frac{V_{{pump}\mspace{14mu} {inlet}}}{V_{{pump}\mspace{14mu} {inlet}} + Q_{f}}} & (19) \end{matrix}$

where V_(pump inlet)—gas volume at the pump inlet in normal conditions calculated based on the following formula:

V _(pump inlet)=(Q _(f) *G*(1−W)*(1−P _(inlet) /P _(bpp))*(P _(atm) /P _(inlet)  (20)

Let's assume that the production rate proportionally depends on the dynamic level, and according to formula (6) define the change in the production rate with the change in dynamic level H_(d) to H_(d.md):

ΔQ _(f) =k*{(H _(d)-H _(d.md))*ρ_(mix) *g}  (21)

When we substitute the values, we define the well-production rate:

ΔQ _(f)=0.11*((1600−1444)*852*9.8)/101325=1.4 m³/day

where 101325 n/m²=1 atm (reduction factor). At the dynamic level of 1444 m the production rate will decrease by 1.4 m3/day and amount to 16.6 m3/day.

Let's calculate the free-gas volume at the pump inlet based on (19):

$\begin{matrix} {V_{{pump}\mspace{14mu} {inlet}} = {{\frac{\phi}{1 - \phi}\mspace{14mu} Q_{f}} = {{\frac{0.25}{1 - 0.25}16.6} = 5.5}}} & (22) \end{matrix}$

Then, based on (20) we define the pump inlet pressure P_(inlet):

$\begin{matrix} {V_{inlet} = {\frac{Q_{f}{G\left( {1 - W} \right)}P_{bpp}P_{atm}}{{V_{inlet}P_{bpp}} + {Q_{f}{G\left( {1 - W} \right)}P_{atm}}} = {\frac{16.6*140*\left( {1 - 0.23} \right)*110*1}{{5.5*110} + {16.6*140*\left( {1 - 0.23} \right)*1}} = {82\mspace{14mu} {atm}}}}} & (23) \end{matrix}$

ESP installation depth depending on dynamic level:

$H_{depth} = {\frac{82*9.8}{0.852} = {943\mspace{14mu} m}}$

ESP hanger depth (vertical, from WH):

H _(depth)=1444+943=2227 m

Based on the directional survey (according to the directional survey log):

H _(meas.depth)=2227+230=2457 m

(230 m according to the directional survey log)

Relative pump temperature in case of operation with a gas content of 0.25 (25%), production rate of 18.6 m3/day at a dynamic level of 1444 m (with the pressure of 82 atm) will be equal to:

a) let's calculate relative pump temperature using the formula (1)

${\Delta \; T} = {{T_{w} - T_{f}} = {\frac{\phi \mspace{14mu} q_{0}R_{2}P_{inlet}P_{bpp}}{1 - {\phi \; 2\left( {1 - W} \right){GP}_{atm}}}\mspace{14mu} \left\{ {\frac{1}{a} + \frac{\delta_{ins}}{\lambda_{ins}}} \right\}}}$

For this purpose, let's calculate q₀: thermal capacity of ESP vessels spent for heat generation. For this purpose:

a) let the nominal capacity of submersible electrical motor N_(nom)=16 kW, efficiency factor of the whole ESP unit be equal to η_(ESP)=0.36;

But in the process of pumping-over the gas-and-fluid mixture with a freegas content at pump inlet of 25%, the efficiency factor drops to 0.2.

Then, the amount of heat generated by the unit is equal to:

Q=N _(nom)*(1-0.2)=16 kW*0.8=12.8 kW  (24)

b) let's calculate the number of vessels in the ESP unit; it is equal to:

$\begin{matrix} {k = {\frac{H}{h} = {\frac{2350}{4} = {587\mspace{14mu} {vessels}}}}} & (25) \end{matrix}$

Of these, the number of vessels pumping over the heavily-gassed mixture to complete gas dissolving in oil (from an inlet pressure of 82 atm to a bubble-point pressure of 110 atm) is equal to:

$k_{p} = {\frac{110 - 82}{0.08} = 350}$

Here, we assume that the average head in the range of 82 to 110 atm is equal to 0.08 atm (20% of nominal head equal to 4 m).

Having assumed that capacity is equally consumed by all of the ESP's operating elements (capacity attributable to 350 pump elements)

$\begin{matrix} {N_{p} = {{\frac{12.8\mspace{14mu} {kW}}{587}350} = {7.63\mspace{14mu} {kW}}}} & (26) \end{matrix}$

c) we will define the thermal capacity q₀ per 350 elements, taking into account that the height of one element is 6 cm, diameter is 10 cm, and that the heat is distributed all over the pump 21 m long (350 elements). Then, the heat-source capacity of 350 elements is equal to:

$\begin{matrix} {q_{0} = {\frac{{.4}N_{p}}{\pi \; d^{2}l} = {\frac{7630*4}{3.14*0.01*21} = {46284\mspace{14mu} W\text{/}m^{3}}}}} & (27) \end{matrix}$

where d—pump diameter, l—pump length, π=3.14.

d) then, the relative temperature (temperature increase in the pump) is equal to:

$\begin{matrix} {{\Delta \; T} = {{T_{w} - T_{f}} = {{\frac{0.25}{1 - 0.25}\frac{46285*0.05*82*110}{2\left( {1 - 0.23} \right)*0.08*140*1}\left\{ {\frac{1}{3800} + \frac{0.001}{8}} \right\}} = {155{^\circ}\mspace{14mu} {C.}}}}} & (28) \end{matrix}$

Let's calculate the absolute temperature of the pump, assuming that the geothermal factor is equal to 0.03° C./m.

For this purpose, let's calculate the mixture temperature at the pump inlet; it is equal to:

T _(f)=82−(2680−2227)*0.03=68° C. at the pump inlet.  (29)

Then, the absolute pump surface temperature will be equal to:

T _(w)=155+68=223° C.  (30)

A temperature of 223° C. is close to the admissible temperature (admissible 230° C.).

A production rate of 16.6 for ESP 5-20-2350 is not acceptable, because for such an inflow, it is necessary to install a wellhead choke at the X-tree, which will result in inefficient power consumption.

Therefore, let's define the ratio:

$\begin{matrix} {Z = {\frac{20}{16.6} = 1.2}} & (31) \end{matrix}$

Let's reduce the AC frequency of the submersible electrical motor Z times.

The frequency is equal to:

$\begin{matrix} {\omega = {\frac{\omega_{st}}{Z} = {\frac{50}{1.2} = {41.7 = {42\mspace{14mu} {Hz}}}}}} & (32) \end{matrix}$

Then, the production rate will amount to 16.6 m3/day. The head will drop to:

$\begin{matrix} {H = {\frac{2350}{1.2^{2}} = {1632\mspace{14mu} {m.}}}} & (33) \end{matrix}$

Head balance: 1632 m=1444 m+50 m+138 m

Total required head is 1900 m. It is evident that a head of 1632 m is insufficient. Therefore, a further reduction in AC frequency is inadmissible.

Let's calculate the change in pump temperature with a reduction in AC frequency. The consumed capacity will drop to:

$\begin{matrix} {N = {\frac{N_{p}}{1.2^{3}} = {\frac{16}{1.44} = {11.1\mspace{14mu} {kW}}}}} & (34) \end{matrix}$

Thermal-source capacity is equal to:

$\begin{matrix} {N_{p} = {{\frac{11,{\text{:}\mspace{14mu} {kW}}}{587}350} = {6.61\mspace{14mu} {kW}}}} & (35) \end{matrix}$

Then, the capacity of the heat source in the pump according to ( ) amounts to:

$\begin{matrix} {\mspace{79mu} {q_{o} = {\frac{6610*4}{3.14*0.01*21} = 40097}}} & (36) \\ {{\Delta \; T} = {{T_{w} - T_{f}} = {{\frac{0.25}{1 - 0.25}\frac{40097*0.05*82*110}{2\left( {1 - 0.23} \right)*0.08*140*1}\left\{ {\frac{1}{3800} + \frac{0.001}{8}} \right\}} = {134{^\circ}\mspace{14mu} {C.}}}}} & (37) \end{matrix}$

Absolute pump temperature is equal to:

T _(w)=134+68=202  (38)

By comparing the temperature gage's (6) and (8) readings, we find the difference ΔT_(t): if

ΔT _(t) ≈ΔT  (39)

with an accuracy of ±5%, then we consider the process of well-rate stabilization completed.

Intermittent Operation:

If, in the process of ESP operation, relative pump temperature increases so that the head drops below the required head:

H _(oper) <H _(d) +H _(d) H _(reg) +H _(ogs)  (40)

where H_(oper)—operating pressure of the centrifugal pump, P_(inlet)-pump inlet pressure, H_(ogs)-pressure in the oil gathering system. That said, it is necessary to shut down the ESP, build the P_(inlet), vs. time curve. Define the time T_(acc) of fluid accumulation in the well to the value of inlet pressure P_(inlet) P_(bpp). The pump is put into operation with a pump temperature of up to T_(w)≤T_(adm); at the same time, we take into account the unit operation time T_(oper). At the same time, we record the current intensity at the initial stage of pumping-out I_(in) and I_(fin), define the initial well-production rate Q_(in) and well production rate before shutdown Q_(fin) (final production rate value). Let's calculate the volume of the lifted fluid as an arithmetic mean:

$\begin{matrix} {Q = {\frac{Q_{i\; n} + Q_{fin}}{2}T_{oper}}} & (42) \end{matrix}$

The unit's operating parameters are provided to the process engineer: volume of produced fluid Q; unit operation time T_(oper); accumulation time (downtime)T_(acc). All process parameters are communicated to the company's process engineer (geologist).

Optimization Mode.

If, after start-up, the pump's inlet pressure becomes constant and higher than the bubble-point pressure, it is necessary to define the additional well-production rate using the following formula:

ΔQ=k(P _(bpp) P _(bh2))  (43)

Let's calculate the change in pump speed (AC frequency) using the following formula:

$\begin{matrix} {Z = \frac{Q_{f} + {\Delta \; Q}}{Q_{f}}} & (44) \end{matrix}$

We increase the current frequency from 50 Hz by 50 Z, define relative temperature. If it is not higher than admissible T_(n,add.), we increase the speed stepwise:

ω=Zω _(i)  (45)

With a further reduction in pump inlet pressure P_(inlet), it is advised to increase AC frequency based on (1).

All process parameters are communicated to the company's process engineer (geologist).

Scalinq Inhibition

To inhibit scaling, we reduce pump temperature to the condition of the beginning of the scaling process T_(salt).

The whole process of rate stabilization will take place according to items 9.1, 9.2, 9.3.

E.g. if the relative temperature of scaling beginning in the well is equal to 46° C., then T_(p,adm).=46° C.

All process parameters are communicated to the company's process engineer (geologist). 

1. A method for operating an oil well by installing an electrical submersible pump (ESP), comprising: installing the ESP in the oil well with a 25% allowance in a pump head at a respective installation depth; determining and entering operating parameters into a control station; checking an integrity of the ESP; setting initial AC frequency ω_(in) at 50 H, setting a ESP temperature limit in such a way that ESP temperature is lower than an admissible temperature T_(p)<T_(adm); recording operating parameters: initial ESP inlet pressure P_(inlet), initial ESP temperature T_(w0), current intensity I; putting the ESP into operation while recording ESP inlet pressure P_(inlet), ESP surface temperature T_(w), and ESP inlet temperature T_(f); operating the ESP up to the ESP's inlet pressure being higher or equal to a bubble-point pressure P_(inlet)≥P_(bpp); when ESP inlet pressure becomes equal to the bubble-point pressure P_(inlet)=P_(bpp), recording temperatures T_(f) and T_(w), defining a well-production rate Q_(f0), stabilizing ESP rate at constant or increasing (by no more than 10%) ESP inlet pressure over one or more hours; recording the following parameters: production rate Q_(f), ESP inlet pressure P_(inlet), ESP inlet temperature T_(f), ESP surface temperature T_(w), current intensity I_(oper), wherein difference between ESP surface temperature T_(w) and ESP inlet temperature T_(f) remains constant or drops by no more than 10% and stabilizes; when ESP inlet pressure P_(inlet) is below the bubble-point pressure P_(bpp) and difference T_(w)−T_(f) is increasing, measuring the following: a bottomhole pressure P_(bh1), K—well productivity factor (m3/day/atm), pressure of a fluid column from bottomhole to a level of ESP suction P_(fl.column), initial ESP inlet pressure P_(inlet0), reservoir pressure P_(res.) equal to the bottomhole pressure in an idle well, and define increase in well-production rate using the following formula: Q ₁ =k(P _(res) −P _(bh1)) at the pressure of P _(bh1) =P _(inlet1) +P _(fl,column), where P_(bh1)—bottomhole pressure, P_(fl,column)=P_(inlet0), K—well productivity factor (m3/day/atm) defined using the formula Q₂=k(P_(res)−P_(bh2)) at the pressure of P_(bh2) P_(inlet2)+P_(fl,column,) where P_(bh2)—bottomhole pressure after operation time t₁; defining difference in increase in well production rate: ΔQ=Q ₂ −Q ₁ =k(P _(inlet1) −P _(bh2)), defining Z ratio: ${Z = \frac{Q_{opt} + {\Delta \; Q}}{Q_{opt}}},$ reducing a ESP speed by Z, and stabilizing unit rate with ESP inlet pressure P_(inlet) above bubble-point pressure, increasing centrifugal ESP speed based on the following relationship: ΔQ _(f) =k(P _(inlet1) −P _(bpp)); calculating AC frequency and current intensity along with measuring of ESP temperature T_(f), continuing ESP operation with values of most optimal production rate Q_(f,optimal), dynamic level H_(d), current intensity of unit I_(oper) and ESP surface temperature T_(w).
 2. The method according to claim 1, wherein the following operating parameters are entered into the control station: k—well productivity factor, m³/day*MPa; initial reservoir pressure—P_(res.), MPa; ESP operating temperature—T_(w).
 3. The method according to claim 1, wherein for purposes of an ESP leak-off test, it is necessary to open a valve, set a rotation direction, close an flowline valve at an X-tree and start up the ESP, pressurize up to 40 atm at the X-tree, switch off the ESP and then check pressure at the X-tree over a course of 15 minutes.
 4. The method according to claim 1, wherein temperatures T_(f) and T_(w) are recorded, and process of a unit start-up is repeated, provided ESP temperature T_(w) is equal to ESP inlet temperature T_(f) and current intensity I_(oper) is equal to
 1. 5. The method according to claim 1, wherein the ESP speed is reduced by Z.
 6. The method according to claim 1, wherein ESP's operation continues with a reduced difference (T_(w)−T_(f)) by more than 10% due to an increase in flow temperature at ESP inlet T_(f), with the values of T_(f), T_(w), well production rate Q_(f), dynamic level H_(d), ESP suction pressure P_(suction), current intensity I_(oper), voltage U_(oper), AC frequency.
 7. The method according to claim 1, wherein the ESP is shut down for accumulation at decreasing ESP suction pressure and increasing ESP temperature up to a value of operating temperature of an extension cable until ESP suction pressure value reaches P_(suction)=1.2 P_(bpp) and provided $H_{{curr}.{head}} = {{\frac{H_{{head}{({\omega \; {st}})}}}{Z^{2}}\mspace{14mu} {at}\mspace{14mu} T_{w}} \geq T_{adm}}$ where H_(curr.head)—current head, H_(head(ωst))—head of the ESP at a standard AC frequency (50 Hz), at the value of P_(suction)=1.2 P_(bpp) the ESP is put into operation with accumulation time t_(acc); pumping-out time t_(pump-out), operating current I_(oper), voltage U_(oper), initial and final ESP surface temperature T_(w, initial), T_(w, final). 